The challenge for all oil and gas companies is to produce as much oil as commercially feasible, leaving as little oil as possible trapped and wasted inside the reservoir. During the primary recovery stage, reservoir drive comes from a number of natural mechanisms. These include natural water pushing oil towards the well, expansion of the natural gas at the top of the reservoir, expansion of gas initially dissolved in the crude oil, and gravity drainage resulting from the movement of oil within the reservoir from the upper regions to lower regions where the wells are located. Recovery factor during the primary recovery stage is typically about 5-15% under such natural drive mechanisms.
Over the lifetime of the well, however, the pressure will eventually fall, and at some point there will be insufficient underground pressure to force the oil to the surface. Once natural reservoir drive diminishes secondary and tertiary recovery methods are applied to further increase recovery.
Secondary recovery methods rely on the supply of external energy into the reservoir in the form of injecting fluids to increase reservoir pressure, hence replacing or increasing the natural reservoir drive with an artificial drive. In addition, pumps, such as beam pumps, gas lift assisted pumping and electrical submersible pumps (ESPs), can be used to bring the oil to the surface. Secondary recovery techniques include increasing reservoir pressure by water injection, CO2 injection, natural gas reinjection, and miscible injection (MI), the most common of which is probably water injection. Typical recovery factor from water-flood operations is about 30%, depending on the properties of oil and the characteristics of the reservoir rock. On average, the recovery factor after primary and secondary oil recovery operations is between 35 and 45%.
While secondary recovery techniques are quite effective, the existence of fractures and highly porous or permeable regions reduces their effectiveness. Any gas or liquid that is injected into a well, will naturally travel the least restrictive route, thus bypassing most of the oil in the less porous or permeable regions. Thus, the overall effectiveness of the sweep is reduced by these so-called “thief zones,” which channel injection fluid directly to production wells.
In such cases, polymers, foams, gelants, emulsions and the like are injected into the thief zones in order to block these zones, thus diverting the subsequent injection fluids to push previously unswept oil towards the production wells. See e.g., FIG. 1.
Among the polymers used for such purposes, partially hydrolyzed polyacrylamide (HPAM) cross linked with Cr (III) gels have been widely used for water shutoff and sweep improvement in field applications. Polymer gels have been applied in enhanced oil recovery to improve the sweep efficiency, prolong the life of an oil well and maximize the recoverable oil amount by placing the gelants deep into the reservoir and blocking the high-permeability channels.
One of the difficulties with the use of polymers to block thief zones, is the issue of viscosity. Viscous polymers are difficult to pump and, in presence of common crosslinking agents such as chromic acetate, gel too quick to place deep in target zones. For this reason, there is considerable effort directed to delaying the crosslinking of polymers until they have already penetrated deep into the oil bearing reservoir.
The idea of using a polyelectrolyte complex for delaying the release of chromium was reported in previous applications US2008058229 (now U.S. Pat. No. 8,183,184) and US20100056399. Those disclosures were directed to novel compositions for delivering, controlling, and delaying the release of an oil and gas field chemical to a target area. The composition comprised a polyanion and a polycation forming a polyelectrolyte complex, and an oil and gas field chemical associated with the polyelectrolyte complex. The oil and gas field chemical was preferably selected from the group consisting of (a) a gel-forming or cross-linking agent, (b) a scale inhibitor, (c) a corrosion inhibitor, (d) an inhibitor of asphaltene or wax deposition, (e) a hydrogen sulfide scavenger, (f) a hydrate inhibitor, (g) a breaking agent, and (h) a surfactant.
In this prior work, one such polyelectrolyte complex was exemplified with a crosslinking agent. The polyelectrolyte complex (PEC) nanoparticle was prepared with polyethylenimine (PEI, Mw 25 kDa) and dextran sulfate (DS). The PEC entrapped and controlled the release of Cr(III). Although the gelation time using PEC nanoparticles was greatly extended compared to chromium (III) acetate used alone (280 times slower than that of the control), the gelation time was still too short for reservoir temperatures higher than 40° C. In addition, the use of chromium is prohibited in some countries due to its toxicity. Furthermore, PEI of 25 kDa is also known for its bias of biodistribution and transfection towards the lungs, causing significant toxicity in vitro and in vivo.
In another U.S. Pat. No. 7,644,764 (US2008223578), we also reported on the delayed gelling made possible with a PEC that lacked metal ions. In that application, a solution comprising PEI and dextran sulfate or chitosan and dextran sulfate was preformed. When mixed with varying amounts of the ALCOFLOOD® 935, gel delay of up to 12 days was observed, but the maximum temperature tested was only 40° C.
Thus, what is needed in the art is PEC nanoparticle system that can provide much longer gelation times at higher temperatures, preferably with less toxicity than the prior art PEC nanoparticle system. In the ideal case, the gelant should have low initial viscosity, extended low viscosity period, long gelation time, and abrupt viscosity increase at the end when gelant becomes gel. Furthermore, the gelant should have both positive and negative charges, allowing its uses to be tailored to various conditions and applications.